The exemplary embodiments described herein relate to systems and methods for optimizing drilling results based on, inter alia, (1) real-time data collected during drilling, (2) a transiently modeled cuttings distribution along the wellbore, and optionally (3) a theoretical change to one or more operational parameters.
Once a prospective reservoir of oil or natural gas in a subterranean formation has been located a drilling rig is set up to drill a wellbore penetrating the subterranean formation. The drilling rig includes power systems, mechanical motors, a rotary turntable drill, and a circulation system that circulates drilling fluid, sometimes called “mud,” throughout the borehole. The fluid serves to remove materials, sometimes called “cuttings,” as the drill bit loosens them from the surrounding rock during drilling and to maintain adequate wellbore pressure.
At least some drilling operations involve rotating a drill bit at the distal end of the pipe, sometimes called “drill string,” and transmitting rotary motion to the drill bit using a multi-sided pipe known as a “kelly” with a turntable. In other drilling operations, the drill bit is rotated with a motor near the drill bit such that the drill string does not rotate. In both cases, as drilling progresses, drilling fluid circulates through the pipe and out of the drill bit into the wellbore. The cuttings are removed from the wellbore by the circulating drilling fluid. New sections are added to the pipe progressively as the drilling continues to extend the drill bit further into the subterranean formation. Once a desired depth is reached, drilling is completed. Various tests can be conducted at this point to precisely locate and isolate portions of the formation housing the desired hydrocarbon deposits.
Drilling operations are extremely expensive and time consuming. For example, drilling operations at an offshore rig can cost in excess of $500,000 to $1,000,000 per day. Therefore, increasing drilling efficiency or productivity, even to a small degree, can lead to huge monetary savings.
The efficiency of a drilling operation is generally determined by the ratio of productive rig time (e.g., time spent drilling) (“PRT”) to non-productive time (“NPT”). During a drilling operation, it is desirable to maximize this ratio because NPT has a cost with minimal to no associated payout. Further, it is desirable to minimize the total time (i.e., PRT plus NPT) to minimize costs.
Minimizing rig time may be achieved by increasing the rate of penetration of the drill bit through the subterranean formation without the equivalent circulating density (“ECD”) exceeding the fracture gradient. Generally, the fracture gradient (which varies along the length of the wellbore) is the pressure at which the formation will fracture, and the ECD is a measure of the pressure that the drilling fluid exerts on the formation. When the ECD exceeds the fracture gradient, the formation will fracture. Unintentional fracturing of the formation can lead to lost circulation that may require remedial operations that contribution to NPT.
In some instances, modeling programs that use steady-state approximations are used to estimate the ECD and compare it to the fracture gradient. Steady-state approximations typically use an average of the drilling parameters/operations and apply those averages to determining an ECD at any point during drilling. For example, a well cleaning method during a drilling operation may average about 5 minutes and be performed on average every 45 minutes. During a well cleaning method, drilling ceases, so cuttings are not produced. This change in concentration of cuttings changes the ECD for that portion of the drilling fluid. Steady-state approximations of ECD would not take into account a well cleaning operation with a different time. This example can be extended to other drilling parameters including rate of penetration into the subterranean formation, length of connection times, and rpm variations for the drill bit. Collectively, these introduce varying levels of error into the modeling program. To account for this error, drilling is performed at an ECD sufficiently lower than the fracture gradient to mitigate formation fracture and resultant fluid loss and lost circulation.